1. Field of the Invention
The invention relates generally to a system for treating process fluids.
2. Background Art
When drilling or completing wells in earth formation, various fluids typically are used in the well for a variety of reasons. As used herein, such fluids will be referred to as “process fluids.” Common uses for process fluids include: lubrication and cooling of drill bit cutting surfaces while drilling generally or drilling-in (i.e., drilling in a targeted petroleum bearing formation), transportation of “cuttings” (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation fluid pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, fracturing the formation in the vicinity of the well, displacing the fluid within the well with another fluid, cleaning the well, testing the well, implacing a packer fluid, abandoning the well or preparing the well for abandonment, and otherwise treating the well or the formation.
In drilling some subterranean formations, and particularly those bearing oil or gas, hydrogen sulfide accumulations are frequently encountered. The drilling fluid brings the hydrogen sulfide to the surface. Such sulfide in the drilling fluid is problematic, as it can corrode the steel in the drilling apparatus and may be liberated into the atmosphere as toxic sulfide gas at the well surface. Further, oil from the drilling fluid (as well as any oil from the formation) maybe become associated with or absorbed to the surfaces of the cuttings that are removed from the formation being drilled. The cuttings may then be an environmentally hazardous material, making disposal a problem.
Generally, to protect the health of those working with the drilling fluid and those at the surface of the well, conditions should be maintained to ensure that the concentration of hydrogen sulfide above the fluid, emitted due to the partial pressure of the gas, is less than about 15 ppm. The partial pressure of hydrogen sulfide at ambient temperatures is a function of the concentration of sulfide ions in the fluid and the pH of the fluid. To ensure that the limit of 15 ppm is not exceeded even for the maximum sulfide concentration that may be encountered in a subterranean formation, the pH of the drilling fluid is typically maintained at a minimum of about 11.5. Also, to prevent the soluble sulfide concentration in the fluid from becoming excessive, action is routinely taken to remove sulfide from the fluid.
Dissolved gases cause many problems in the oil field. Gases and other fluids present in subterranean formations, collectively called reservoir fluids, are prone to enter a wellbore drilled through the formation. In many cases, dense drilling fluids, completion brines, fracturing fluids, and so forth are provided to maintain a countering pressure that restrains the reservoir fluids from entering the wellbore. However, there are many instances where the counter pressure is too low to restrain the reservoir fluids. This may be due to, for example, a miscalculation of the fluid density needed to maintain a hydrostatic overbalance or a transient lowering of pressure due to movement of the drill string in the hole. Gasses may also enter the wellbore through molecular diffusion if there is insufficient flux of fluid from the wellbore to keep it swept away. Finally, reservoir fluids escape from the fragments of the formation that are being drilled up. The reservoir fluid that enters the well is then free to mix with the supplied well fluid and rise to the surface.
The hazards of un-restrained expansions of reservoir fluids in the wellbore are well known. A primary hazard is an avalanche effect of gas evolution and expansion, wherein gas bubbles rise in a liquid stream, expanding as they rise. As the bubbles expand, they expel dense fluid from the bore, and further reduce the hydrostatic pressure of the wellbore fluid. Such a progression may eventually lead to a ‘blow out,’ whereby so much restraining pressure has been lost that the high pressure reservoir can flow uncontrollably into the wellbore.
Less dramatic, but equally important, are chemical effects that formation fluids may have upon the circulating fluid, the structure of the well, and the associated personnel. These effects and risks may include, for example: methane gas liberated at the surface may ignite; carbon dioxide may become carbonic acid, a highly corrosive compound, when exposed to water; carbon dioxide gas is an asphyxiant; hydrogen sulfide can corrode ferrous metals, particularly in contact with water, and is more damaging than carbon dioxide because it can induce hydrogen embrittlement; embrittled tubulars may separate or break well under design stresses with catastrophic consequences; hydrogen sulfide gas is also toxic, with levels of 800 to 1000 ppm causing death in healthy individuals. Removing dissolved and entrained gases is thus vital to many aspects of successful drilling and exploitation.
Process fluids from wells are typically sent offsite for treatment and processing to remove hazardous materials from the process fluid. For example, gases, such as hydrogen sulfide, solids, for example amounts of earth formation, cuttings, debris, etc., and other fluids, for example oil, may be removed from the process fluid during such processing of the process fluid so that the process fluid may be safely disposed or re-circulated to the well. Sending process fluids offsite may be cumbersome and costly due to the potential risks involved, including health risks for personnel handling the transport of the process fluids and environmental risks of leakage or spillage of the process fluid during transportation.
Accordingly, there exists a need for a system and method for treating a process fluid, including facilitating the reduction of entrained and dissolved gases in the process fluid.